Catalytic down-hole upgrading of heavy oil and oil sand bitumens

ABSTRACT

The invention relates to systems and methods for catalytic down-hole upgrading of heavy oil and oil sand bitumens. The method enables upgrading heavy oil in a production well within a hydroprocessing zone including the steps of: introducing a controlled amount of heat to the hydroprocessing zone; introducing a selected quantity of hydrogen to the hydroprocessing zone to promote a desired hydrocarbon upgrading reaction; and, recovering upgraded hydrocarbons at the surface. The invention further includes the hardware capable of performing the method.

FIELD OF THE INVENTION

The invention relates to systems and methods for catalytic down-holeupgrading of heavy oil and oil sand bitumens. The method enablesupgrading heavy oil in a production well within a hydroprocessing zoneincluding the steps of: introducing a controlled amount of heat to thehydroprocessing zone; introducing a selected quantity of hydrogen to thehydroprocessing zone to promote a desired hydrocarbon upgradingreaction; and, recovering upgraded hydrocarbons at the surface. Theinvention further includes the hardware capable of performing themethod.

BACKGROUND OF THE INVENTION

Heavy oil and bitumen are highly viscous oils that are difficult toproduce and require upgrading before being sent into refineries. Costlyprocessing methods and problematic transportation make heavy oils areasonable substitute for conventional oil only when energy prices arehigh enough to justify their processing costs. Due to the sharp increasein oil prices in the 21st century, special attention has been paid toheavy oil and bitumen resources.

Heavy oil like any kind of petroleum or crude oil consists of a widerange of constituents mainly mixtures of hydrocarbons and compoundscontaining sulfur, nitrogen, oxygen and metals. Metals are typicallyvanadium and nickel and their percentage in the petroleum increases inmost viscous oils. The physical properties of petroleum vary widelydepending on its constituents and their amounts.

The definition of a heavy oil is normally based on its API gravityand/or viscosity and is quite arbitrary. A commonly accepted definitionclassifies the heavy oil as petroleum whose API gravity is between 10and 20. Also, heavy oils usually and not always have sulfur contents ofhigher than 2 wt %. In the case of bitumen, the term refers to the oilproduced from bituminous sand formations that are used to recover thebituminous material by mining operations.

The physical properties and chemical composition of oil change not onlybased on geographical location but also with the depth of the oil in aparticular location and will normally contains small amounts of organicmaterials containing sulfur, oxygen and nitrogen as well as metalliccompounds such as nickel, iron, and copper. For lighter oils the amountof hydrocarbon molecules can be as high as 97% and for heavy oil andbitumen can be as low as 18%. Table 1 shows a range of each mainconstituent of a typical light and heavy petroleum:

TABLE 1 Light and Heavy Petroleum Constituents Element Light HeavyCarbon: 83.0% to 87.0% 83.4 ± 0.5%  Hydrogen: 10.0% to 14.0% 10.4 ±0.2%  Nitrogen: 0.1% to 2.0% 0.4 ± 0.2% Oxygen: 0.05% to 1.5% 1.0 ± 0.2%Sulfur: 0.05% to 6.0% 5.0 ± 0.5% Metals (Ni and V) <1000 ppm >1000 ppm

Oil is also classified in the following general classifications based onthe average boiling point of its constituents.

Gases & Naphtha: The main constituent of petroleum gases is methane. Theother major hydrocarbons are ethane, propane, butane, isobutene and someC4+ alkanes.

Middle Distillates: The main portion of this fraction is comprised ofthe saturated species; however, aromatics and heterocyclic compoundsrepresent a considerable portion. Most of the aromatics are di- andtri-methyl naphthalenes. The percentage of the sulfur molecules is verylow. Trace amounts of both basic and neutral nitrogen compounds arenormally present. The boiling range is typically between 180° C. and340° C.

Vacuum Gas Oils: The boiling range for the vacuum gas oil (VGO) isbetween 340° C. and 540° C. The quantity of the aromatics (mono- anddi-aromatics) is greater than the saturates. Saturated compounds in VGOconsist of iso-paraffins and naphthene species. Heterocyclic compoundsare also significant in VGOs. The major sulfur compounds are thethiophenes (mostly benzothiophenes and dibenzothiophenes) andthiacyclane sulfur which are present in greater amounts than sulfidesulfur.

Vacuum Residue: This fraction is the most complex fraction and containsthe majority of heteroatom molecules of the petroleum whose boilingpoints are over 540° C. Characterization of individual constituents ofthis fraction may utilize various empirical/semi-empiricalthermo-physical models based on the observed functionalities, apparentmolecular weight and elemental analysis.

Heavy Oil Production from Oil Sands

Oil sands are deposits of bitumen and are found in 70 countries withthree quarters of world reserves located in Canada and Venezuela.Production of heavy and extra-heavy oils in Canada started some 38 yearsago by surface mining the Athabasca oil sands. As of Dec. 31, 2005,Canada's proven oil reserves are estimated as 177.9 billion barrels fromwhich 173.7 billion is in the form of oil sands.

The production of bitumen from oil sands has been revolutionized in therecent years. Today less than 10% of bitumen production occurs throughmining. Enhanced oil recovery techniques (discussed below) enableproducing reserves that are deeper than 75 meters under the groundsurface. Most of the in-situ production of bitumen and heavy oil comesfrom deposits buried more than 400 meters.

The most common in-situ production methods are Cyclic Steam Stimulation(CSS) and Steam Assisted Gravity Drainage (SAGD) which require theinjection of hot fluids into the reservoir. Canada's largest in-situbitumen production projects are at Cold Lake where deposits are heatedby steam injection and the bitumen is brought to the surface and laterdiluted with condensates for pipeline transportation.

In-situ technology in recent years has been a subject of study for usein down-hole upgrading processes. The in-situ upgrading that has beentargeted in research projects includes hydrotreating of oil, mostlyhydrodenitrogenation and hydrodesulfurization, hydrocracking andasphaltene precipitation. These upgrading projects mostly do not providea high degree of upgrading in terms of contaminant removal and APIgravity increase.

Traditionally oil recovery methods are divided into three categories:primary, secondary and tertiary based on their chronological order inproduction. Primary recovery is accomplished by the natural energy ofthe oil reservoir, secondary recovery is based on the energy ofinjection of gas or water to displace oil towards the production welland tertiary recovery use miscible gases, chemicals and thermal energyto displace the oil and are implemented when secondary methods becomeuneconomical.

As heavy oil reservoirs cannot be produced based on their natural energyor waterflooding, the term EOR (Enhanced Oil Recovery) is used todescribe chemical and thermal methods for heavy oil recovery. Examplesof EOR processes are injections of gases such as nitrogen and CO₂,injection of liquid chemicals including polymers, surfactants andhydrocarbon solvents and thermal methods such as steam or hot waterinjection or in-situ generation of thermal energy.

Upgrading

Upgrading is generally defined as any treatment of bitumen or heavy oilthat increases its value. Therefore, the minimum objective is to reducethe viscosity of oil and the maximum objective is to obtain a crude oilsubstitute of higher quality.

Hydroprocessing reactions are thermal processes that take place in thepresence of hydrogen. Such reactions can be both destructive andnon-destructive. Destructive hydrogenation (hydrogenolysis andhydrocracking) is conversion of higher molecular weight compounds tolower-boiling point compounds. Non-destructive hydrogenation orhydrotreating are simple hydrogenation reactions during which thequality of oil improves by removing certain contaminants of oil from itsmolecular structure such as sulfur (hydrodesulfurization (HDS)),nitrogen (hydrodenitrogenation (HDN)) and metals. Generally speaking thereactivity of the hydroprocessing reactions increases in the followingorder:

Hydrocracking<HDN<HDS

The reaction conditions vary in the different processes, however atypical temperature range is 300-345° C. and the hydrogen partialpressure can be in the range of 500 to 1000 psi.

The catalyst used in hydrotreating reactions is normallycobalt-molybdenum with typically 10% molybdenum oxide and less than 1%cobalt oxide and the support is alumina. However, a wide range of metalscan be effective: cobalt, iron, nickel promoted copper and copperchromite. The type of catalyst that is used in each process can changebased on the immediate objective. For example, CoMo type formulae aregenerally used for HDS reactions, the NiMo type are employed forhydrogenation and HDN reaction and the NiW type are used forhydrogenation of very low sulfur cuts. The existence of sulfur andmetals is a challenge in hydrotreating reactions because these compoundspoison the catalyst. Therefore, more resistant catalysts are used suchas CO—Mo—Al₂O₃.

Hydrocracking is the reaction between hydrogen and oil fractions, mostlyvacuum distillates and residue, in which the reactants crack intolighter fractions. Based on the objective chosen with respect to theextent of conversion and the quality of the products, hydrocracking canbe divided into mild hydrocracking and conventional hydrocracking. Bothof these two hydrocracking processes are similar with respect to thereactions, however, the products and their quality can vary because ofthe different reaction conditions. Mild hydrocracking normally takesplace at some 50-80 bar (5-8 MPa) total pressure and temperature of350-430° C., where conventional hydrocracking, the total pressure isabout 100-200 bar (10-20 MPa) and the temperature is between 380-440° C.The mechanism of hydrocracking is similar to that of catalytic crackingbut includes concurrent hydrogenation. The products of hydrocracking areeither saturated or aromatic rings but not olefin.

An important hydrocracking reaction is the partial hydrogenation ofpolycyclic aromatics and the ultimate rupture of saturated rings tomonocyclic aromatics. In the case of residue, hydrocracking is used forprocesses such as desulfurization and residue conversion to lowerboiling distillates.

The reactions take place in the presence of dual-function catalysts.Silica-alumina catalyst promotes cracking reactions where platinum,tungsten oxide, or nickel contributes to hydrogenation reactions.

One major difference between hydrocracking and hydrotreating is theresidence time and the extent of the decomposition of the non-heteroatomconstituents. The upper limits of hydrotreating often overlap with thelower limits of hydrocracking.

The main advantages of down-hole upgrading include the reduction inrefinery and upgrading costs, the reduction in size of surface upgradingfacilities and the utilization of the pre-introduced heat from thermalprocesses.

Examples of past systems and methods of upgrading oil include U.S. Pat.No. 6,964,300 which describes a process of in situ thermal recovery froma permeable formation using a heater within the wellbore; U.S. Pat. No.6,742,593 which describes in situ thermal processing of a hydrocarboncontaining formation using heat; U.S. Pat. No. 7,121,342 which describesthermal processes for subsurface formations; U.S. Pat. No. 6,996,374which teaches a method of increasing hydrocarbon mobility within apermeable formation using gas; US patent application 2003/0062163 whichteaches a method of in situ upgrading; U.S. Pat. No. 3,817,332 whichteaches a method and apparatus of catalytically heating a wellbore; USPatent application 2006/017053 which teaches a process for improvingextraction of crude oil by circulating hot hydrocarbons in order to heatan underground reservoir; U.S. Pat. No. 6,056,050 which teachesinjecting steam through a horizontal well into a formation for enhancingviscous oil recovery; US Patent application 2006/0231455 which teaches amethod for producing and upgrading oil; US Patent application2005/0239661 which discloses a downhole catalytic combustor for enhancedheavy oil mobility; and U.S. Pat. No. 4,597,441 which teaches a recoveryof oil by in situ hydrogenation.

SUMMARY OF THE INVENTION

In accordance with the invention, there is provided a method ofupgrading heavy oil in a production well within a hydroprocessing zonecomprising the steps of: introducing a controlled amount of heat to thehydroprocessing zone; introducing a selected quantity of hydrogen to thehydroprocessing zone to promote a desired hydrocarbon upgradingreaction; and, recovering upgraded hydrocarbons at the surface.

In further embodiments of the invention, a catalyst is introduced to thehydroprocessing zone where the catalyst may be a nano-particle catalystthat may be circulated within the hydroprocessing zone.

The hydroprocessing zone is preferably a vertical section of a wellborewhere heavy oil is preferably separated from water prior to introducingheavy oil into the hydroprocessing zone. In various embodiments, thecatalyst is a bi-metallic catalyst of the general formula:B_(x)M_(y)S_([(1.1 to 4.6)y+(0.5 to 4)x]) where B is a group VIIIBnon-noble metal and M is a group VI B metal and 0.05≦y/x≦15. In oneembodiment, 0.2≦y/x≦6 or y/x=3. The catalyst may be tri-metalliccatalysts of the general formula: B_(x)M1_(y)M2_(z)O(2 to3)_(z)S_([(0.3 to 2)y+(0.5 to 4)x]) where B is a group VIIIB non-noblemetal and M1 and M2 are group VI B metals and 0.05≦y/x≦15 and 1≦z/x≦14.In one embodiment the y/x ratio is in the range of 0.2<y/x<6 and in morespecific embodiments 10<z/x<14 or z/x=12. In another embodiment, 1<z/x<5and the upgrading process is mild hydrocracking. In another embodiment,z/x=3 and the upgrading process is mild hydrocracking. Other upgradingreactions may be hydrodenitrogenation and hydrodesulfurization.

Heat may be introduced to the one or more hydroprocessing zones (wheredifferent hydroprocessing reactions may occur) using any one of or acombination of electrical, hot fluid, or an in-well combustion device.

In another embodiment, the method of the invention, controls thereaction parameters in different areas of the hydroprocessing zone so aspromote different hydroprocessing reactions in different areas.

In yet another embodiment, the upgrading process is part of a steamflooding process including any one of steam assisted gravity drainage(SAGD), vapor extraction (VAPEX), cyclic steam stimulation (CSS) andCAPRI.

In another embodiment, the invention provides a system for upgradingheavy oil in a production well within a hydroprocessing zone comprising:a downhole heater for introducing a controlled amount of heat to thehydroprocessing zone; a hydrogen delivery system for introducing aselected quantity of hydrogen to the hydroprocessing zone to promote adesired hydrocarbon upgrading reaction; and, a surface recovery systemfor recovering upgraded hydrocarbons at the surface. The system may alsoinclude a downhole water separator for separating water from heavyhydrocarbon, the downhole water separator operatively located upstreamof the hydroprocessing zone.

DESCRIPTION OF THE DRAWINGS

The invention is described with reference to the drawings in which:

FIG. 1 is a schematic diagram of an in situ upgrading system havinghorizontal and vertical wells;

FIG. 2 is a schematic diagram of an in situ upgrading system whereproduction and injection take place through the same well;

FIG. 3 is a schematic diagram of an in situ upgrading system whereproduction and injection wells are located a distance from each other;

FIG. 4 is a schematic diagram of an in situ upgrading system using aTHAI configuration;

FIG. 5 is a schematic diagram of a two-stage separator within awellbore;

FIG. 6 is a schematic diagram of horizontal wellbore segments and feedstreams entering each segment;

FIG. 7 is a diagram of a HYSYS interface showing horizontal wellboresegments and entering feed streams;

FIG. 8 is a schematic diagram of vertical wellbore segments in seriesconfiguration;

FIG. 9 is a diagram of a HYSYS interface showing the vertical wellboreand the inlet streams;

FIG. 10 is diagram showing a network of hydrocracking reactions betweenvarious oil fractions;

FIG. 11 is a diagram showing a simplified hydrocracking network;

FIG. 12 shows HDS conversion percent for non-residue lumped fractions(Diam. 15 cm—production rate 1.39 m3/h);

FIG. 13 shows HDS conversion percent for residue fraction (Diam. 15cm—production rate 1.39 m3/h);

FIG. 14 shows HDN conversion percent for non-residue lumped fractions(Diam. 15 cm—production rate 1.39 m3/h);

FIG. 15 shows HDN conversion percent for residue fraction (Diam. 15cm—production rate 1.39 m3/h);

FIG. 16 shows HDS and HDN conversion percent at 350° C. for non-residuelumped fractions (Diam. 15 cm—production rate 1.39 m3/h);

FIG. 17 shows HDS and HDN conversion percent at 350° C. for residuefraction (Diam. 15 cm—production rate 1.39 m3/h);

FIG. 18 shows weight percent of residue sulfur compounds, non-residuelumped fractions sulfur compounds and the total sulfur compounds in feedand HDS product streams at various wellbore lengths at 350° C. (Diam. 15cm—production rate 1.39 m3/h);

FIG. 19 shows weight percent of residue nitrogen compounds, non-residuelumped fractions nitrogen compounds and the total nitrogen compounds infeed and HDN product streams at various wellbore lengths at 350° C.(Diam. 15 cm—production rate 1.39 m3/h);

FIG. 20 shows Composition of feed (typical Alberta bitumen);

FIG. 21 shows Volume percent change due to hydrocracking on conventionalcatalyst at 425° C. (Diam. 15 cm) —SOR 0;

FIG. 22 shows Volume percent change due to hydrocracking on conventionalcatalyst at 350° C. (Diam. 15 cm) —SOR 0;

FIG. 23 shows volume percent change due to hydrocracking on conventionalcatalyst at 375° C. (Diam. 15 cm) —SOR 0 ;

FIG. 24 shows volume percent change due to hydrocracking on conventionalcatalyst at 403° C. (Diam. 15 cm) —SOR 0;

FIG. 25 shows volume percent change due to hydrocracking on conventionalcatalyst at 100 m wellbore (Diam. 15 cm) —SOR 0;

FIG. 26 shows volume percent change due to hydrocracking on conventionalcatalyst at 200 m wellbore (Diam. 15 cm) —SOR 0;

FIG. 27 shows volume percent change due to hydrocracking on conventionalcatalyst at 300 m wellbore (Diam. 15 cm) —SOR 0;

FIG. 28 shows Volume percent change due to hydrocracking on conventionalcatalyst at 500 m wellbore (Diam. 15 cm) —SOR 0;

FIG. 29 shows Volume percent change due to hydrocracking on conventionalcatalyst at 425° C. (Diam. 10 cm) —SOR 0;

FIG. 30 shows Volume percent change due to hydrocracking on conventionalcatalyst at 350° C. (Diam. 10 cm) —SOR 0;

FIG. 31 shows Volume percent change due to hydrocracking on conventionalcatalyst at 375° C. (Diam. 10 cm) —SOR 0;

FIG. 32 shows Volume percent change due to hydrocracking on conventionalcatalyst at 403° C. (Diam. 10 cm) —SOR 0;

FIG. 33 shows Volume percent change due to hydrocracking on conventionalcatalyst at 100 m wellbore (Diam. 10 cm) —SOR 0;

FIG. 34 shows Volume percent change due to hydrocracking on conventionalcatalyst at 200 m wellbore (diam. 10 cm) —SOR 0;

FIG. 35 shows Volume percent change due to hydrocracking on conventionalcatalyst at 300 m wellbore (Diam. 10 cm) —SOR 0;

FIG. 36 shows Volume percent change due to hydrocracking on conventionalcatalyst at 500 m wellbore (Diam. 10 cm) —SOR 0;

FIG. 37 shows Volume percent change due to hydrocracking on conventionalcatalyst at 350° C. (Diam. 15 cm) —SOR 1;

FIG. 38 shows Volume percent change due to hydrocracking on conventionalcatalyst at 375° C. (Diam. 15 cm) —SOR 1;

FIG. 39: Volume percent change due to hydrocracking on conventionalcatalyst at 403° C. (Diam. 15 cm) —SOR 1;

FIG. 40 shows Volume percent change due to hydrocracking on conventionalcatalyst at 425° C. (Diam. 15 cm) —SOR 1;

FIG. 41 shows Volume percent change due to hydrocracking on conventionalcatalyst at 100 m wellbore (Diam. 15 cm) —SOR 1;

FIG. 42 shows Volume percent change due to hydrocracking on conventionalcatalyst at 200 m wellbore (Diam. 15 cm) —SOR 1;

FIG. 43 shows Volume percent change due to hydrocracking on conventionalcatalyst at 300 m wellbore (Diam. 15 cm) —SOR 1;

FIG. 44 shows Volume percent change due to hydrocracking on conventionalcatalyst at 500 m wellbore (Diam. 15 cm) —SOR 1;

FIG. 45 shows Volume percent change due to hydrocracking on conventionalcatalyst at 350° C. wellbore (Diam. 15 cm) —SOR 10;

FIG. 46 shows Volume percent change due to hydrocracking on conventionalcatalyst at 375° C. wellbore (Diam. 15 cm) —SOR 10;

FIG. 47 shows Volume percent change due to hydrocracking on conventionalcatalyst at 403° C. wellbore (Diam. 15 cm) —SOR 10;

FIG. 48 shows Volume percent change due to hydrocracking on conventionalcatalyst at 425° C. wellbore (Diam. 15 cm) —SOR 10;

FIG. 49 shows API gravity increase for SOR 0—conventional catalyst;

FIG. 50 shows API gravity increase for SOR 1—conventional catalyst;

FIG. 51 shows API gravity increase for SOR 10—conventional catalyst;

FIG. 52 compares the API gravity increase at 425° C. for SOR 0 and SOR1—conventional catalyst;

FIG. 53 compares the API gravity increase at 403° C. for SOR 0 and SOR1—conventional catalyst;

FIG. 54 shows volume percent change due to hydrocracking on UD catalystat 425° C. wellbore (Diam. 15 cm)

FIG. 55 shows Volume percent change due to hydrocracking on UD catalystat 350° C. wellbore (Diam. 15 cm);

FIG. 56 shows Volume percent change due to hydrocracking on UD catalystat 375° C. wellbore (Diam. 15 cm);

FIG. 57 shows Volume percent change due to hydrocracking on UD catalystat 403° C. wellbore (Diam. 15 cm);

FIG. 58 shows API gravity increase for SOR 0—UD catalyst;

FIG. 59 compares the API gravity increase at 425° C. for SOR 0

FIG. 60 compares the API gravity increase at 403° C. for SOR 0; and,

FIG. 61 compares the API gravity increase at 375° C. for SOR 0.

DETAILED DESCRIPTION OF THE INVENTION

In accordance with the invention and with reference to the figures,systems and methods for upgrading hydrocarbons within a petroleumreservoir are described. In particular, the methods enable upgrading ofheavy, extra heavy and shale oils and bitumen within a production wellbore using selective downhole heating elements, hydrogen and catalystinjection so as to integrate exploitation with in-situ upgrading. Themethods of the invention are particularly applicable to steam-assistedgravity drainage (SAGD) and vapor extraction (VAPEX), and cyclic steamstimulation (CSS) recovery methodologies.

In a preferred embodiment, as shown in FIG. 1, the invention provides asystem for hydrocarbon upgrading in a well bore system having bothhorizontal and vertical sections. As discussed below, the methodologiesof the invention may be applied to other EOR techniques including wellshaving only a single vertical section. As shown in FIG. 1, thehorizontal section 10 serves to collect the hot oil/water mixture feed11 via perforations 12 on its surface, with any one of or both of thehorizontal section 10 and/or vertical section 14 serving as a reactorwith reactor elements. The temperature of the feed is increased by heatintroduced to the body of the well by any one of or a combination ofelectrical, combustion, hot gases or other localized heaters 15 inaccordance with various EOR techniques discussed below. Within thehorizontal and/or the vertical section, the feed 11 may be mixed withhot hydrogen injected into the well via a gas liner 16 within thevertical section 14 and/or horizontal sections 10 of the well.

In Situ Upgrading

In accordance with the invention and with reference to the figures,down-hole or in-situ upgrading processes are described for various EORmethodologies. Such processes have been a previously unsuccessfulalternative to conventional upgrading processes as a result of thedifficulties of placing catalyst underground, treating the abundantamounts of brine, high partial pressure of steam and low partialpressure of hydrogen. However, as detailed below, there are advantagesin down-hole upgrading by employing the down-hole energy (up to 35 MPaand 80° C.), and the porous media (mineral formation) that can act as anatural chemical catalytic reactor.

Generally, the process of in-situ upgrading includes:

-   -   Placement or formation of catalyst in an oil bearing medium;    -   Mobilization of oil components over the catalyst;    -   Introducing co-reactants such as hydrogen to the reaction        environment; and,    -   Creating the necessary conditions for the reactions;

There are two main routes for chemical reaction upgrading, namely theaddition of hydrogen, or hydrogen donors and carbon rejection. Hydrogenaddition results in hydrogenation and little carbon deposition becausethe by-products are mostly hydrogen sulfide or light hydrocarbons whichare mostly gaseous that will automatically exit the wellbore. Gases mayalso contribute to production increases because of their miscibility inthe oil and contribution to reducing viscosity. Another advantage ofthis process is hydrogenation of carbon deposits.

Carbon rejection is beneficial as it leaves highly carbonaceousmaterials in the wellbore and produces upgraded oil. However, thedeposition of such materials in the reaction medium will contribute towellbore plugging and catalyst deactivation. Furthermore, most oilreservoirs also contain significant amounts of brine that will have asignificant effect in down-hole upgrading of heavy oils.

Further still, any injected gas, in order to have a reasonable partialpressure to react, must have a higher pressure than that of injectedsteam. As the saturated steam pressure at 300° C. is about 1235 psi, fora wellbore with reaction temperatures of 250-350° C. to contain steam, adepth of 1150 to 2800 feet is required. In other words at suchconditions the gas must be injected at over 1200 psi for a length ofsome 2000 feet.

Different processing scenarios can be implemented for down-holeupgrading:

In one embodiment, a catalyst bed is placed in an oil-bearing intervalby gravel packing, proppant injection, or water injection as shown inFIG. 2. Oil flows over the catalyst either naturally or by induced drivemechanisms. Oil is produced through the perforations in the well casingand is directed to the surface by the production tubular. An injectiontubular is used to inject heated fluids, such as hydrogen or hydrogendonors into a volume below the catalyst bed.

In another embodiment, as shown in FIG. 3, the catalyst is placed inclose vicinity to the production well; however, the injection process isthrough the injection well, placed a further distance from theproduction well. Thermal drive is induced by a combustion front. Thecombustion produces hydrogen and carbon monoxide which mobilizes the oilfront. At the same time, water transfers heat ahead of the combustionfront by steam override. In this configuration, additional heat can alsobe provided through the production zone as per FIG. 1.

In a further embodiment as shown in FIG. 4, catalyst is placed inside oraround a horizontal production well, where a vertical injection wellinjects hot air into the reservoir. This method is called CAPRI and isthe catalytic form of Toe to Heel Air Injection (THAI) method. Theupgrading extent is higher than THAI because of the use of the catalystin the system.

In a further embodiment, Steam Assisted Gravity Drainage (SAGD) (notshown) methodologies are utilized with catalyst placed or injectedinside the wellbore. In a SAGD production method, two parallel wellsexist including an upper well for steam injection well and a lower oneas the production well. The steam injection well drives the oil into theother horizontal well underneath. Oil contacts catalyst placed insidethe production well, and the upgrading reactions are promoted as the oilmoves towards the vertical well. Catalyst can either be a solid fixedbed or an ultra dispersed catalyst in the liquid phase.

Brine

As previously mentioned, the presence of significant volumes of brineposes a major challenge in down-hole upgrading. DOWS (down-hole oilwater separation) technology typically consists of a separation and apumping stage. In one design (not shown), gas is separated from theliquid through gravity separation without introduction of anycentrifugal force, nozzles or other types of mechanisms utilizing thedifference in the density of the two phases as the factor in theseparation. This design involves the installation of a pump intake belowthe lowest point of fluid entry into the wellbore and requires an opencasing-tubing annulus along the wellbore. The gas bubbles rise throughthe liquid phase and leave its surface and move upwards in thecasing-tubing annulus. The liquid phase is accumulated at the bottom ofthe well and enters the pump intake to be discharged into the tubing.

In an alternative design, separation occurs in two stages as shown inFIG. 5. In the first stage, separation of gas from liquid occurs in thewellbore tubing-casing annulus. The gas bubbles leave the gaseous liquidin the annulus and move upwards in the casing. The remaining mixture ofgas and liquid enters the second stage down-hole gas separator throughan anchor port and its perforations on its surface leading to furtherseparation. In this system, the amount of gas that flows with the liquidinto the tube and to the pump intake is minimized.

Upgrading Conditions Pressure

Hydrostatic pressure is the means to obtain the upgrading reactionpressures and is calculated from

P=ρgh

where ρ is the density of the ground above, g is the earth's gravity andh is the depth of the wellbore.

Energy

To provide the energy to the reaction medium various methods can beutilized such as introducing hot fluids, steam injection or fireflooding. Other methods use point sources including down-hole steamgeneration or combustion, electromagnetic stimulation and down-holeheating with electric coils.

Down-hole gasification or combustion may be utilized for sub-terrainheating. As noted a mixture of fuel and air are injected into thewellbore and are ignited creating a front that moves towards theproduction well. Wet oxidation can been used to inject steam under aformation at 315-340° C. and 2000-2500 psi. A heat conductive systemthat employs a down-hole gas-fired burner is capable of heating atransfer fluid to 815-1400° C. Another benefit of down-hole heating isthe generation of CO which in proper conditions controls the extent ofoxidation (together with combustion or partial oxidation catalysts),produces H₂ through the water-gas shift reaction.

A particular benefit is that operation of a down-hole steam generator orgasifier below a catalyst zone produces upward flow of heat andcombustion gases that can provide heat and H₂ (or CO) for upgrading.

Catalyst

Catalyst is normally placed in the vicinity of the well either byinjecting a liquid phase solution or adding solid catalyst particlesaround the wellbore.

In the case of solid particles, and where recovering the catalyst is notpractical, used or regenerated hydroprocessing catalysts may beappropriate for placement. The major problem associated with solid-phasecatalyst is the collection of impurities on the catalyst area resultingin the deactivation of catalyst and also greater pressure drops withtime.

Injection of homogenous catalyst occurs in the area surrounding theproduction well. Fluid phase catalyst reaches further distances from thewellbore; therefore, an advantage is that if plugging occurs due to thereactions, it will be away from the wellbore and will have less severeeffects on production rates.

Homogenous catalysts mostly have similar active metals to those ofheterogeneous catalysts, mainly molybdenum and iron. The additives aremostly cobalt and nickel and the sulfide metal is the active phase. Anadvantage to using a fluid phase catalyst is that it can be prepared inremote areas. For example amines such as ethylene diamine can be addedto aqueous ammonium heltamolybdate and cobalt nitrate mixtures whichstabilizes the solution and allows the metals to be deposited in areasremote from solution preparation.

Homogenously dispersed catalysts can also be used for combustioncatalytic upgrading. Aqueous phase iron or tin salts dispersed in amixture of sand/oil/water in a combustion tube experiment resulted inincreased fuel deposition, higher velocity of combustion front and loweroxygen combustion.

Methodology

A wellbore consisting of both horizontal and vertical sections wasstudied as per FIG. 1 although it is understood that the upgradingtechnologies described herein may be applied to other EOR techniques asunderstood by those skilled in the art. The horizontal well collects themixture of oil and steam via the perforations on its surface and directsthem to the vertical section. The total length of the horizontal sectionmay be varied based on the well location and reservoir length. In thisdescription, the length of this section was assumed to be 1000 meters.The vertical well may also have different lengths which will result invarious residence times for the upgrading reactions. The down-holetemperature of oil was assumed to be 220° C. as a typical hightemperature of SAGD steam injection.

To evaluate the effectiveness of in-situ upgrading, a HYSYS simulatorwas used (Aspen Tech., Houston). This simulator offers a comprehensiveOil Manager which allows introducing various oil assays to the model andthe creation of pseudo-components based on the desired assay. Also thereaction package provides a high level of control over the reactionstoichiometry, kinetics, units and the phases. Finally the simulatorencompasses a comprehensive set of objects and unit operations thatpermit simulation of the wellbore with high level of control over eachsegment.

As shown in FIG. 1, the model consists of the vertical and horizontalsections of a wellbore and the upgrading sections. The oil enters thewellbore through the perforations and the entrance point. The fluidsthen pass through an optional steam/water separator 50, followed by flowinto the vertical wellbore where the oil is mixed with the injectedstream of ultra dispersed catalyst and hydrogen gas. The mixture of oil,catalyst and hydrogen moves upwards where it is heated and thehydroprocessing reactions take place. At the end of the vertical well,the produced oil is partially upgraded.

HYSYS Fluid Package

Simulation models in HYSYS are created based on previously defined fluidpackages. The choice of any package is based on the specific systemunder consideration (the components that are involved and theirinteraction) and also the operating conditions.

The main thermodymic package choice is either the Equation of State orthe Activity Model. The Equation of State chosen for this model isPeng-Robinson which was developed originally to deal with hydrocarbongas models. This model has been shown to be very efficient for mosthydrocarbon based fluids over a wide range of operating conditions.

Simulation Components

In a flowsheet simulation, components can either be defined as pure orpseudo-components. Pure components are specific chemical compounds suchas water or hydrogen. The pseudo-components, which are calledhypothetical components in HYSYS, are not pure but are treated as those.Their definition is based on the objective and nature of the simulationand can vary.

In refinery simulations, a major advantage of defining pseudo-componentsis to limit the number of components in the system by grouping them intolimited number of groups. This significantly decreases the computationtime needed for analyzing the components of a stream without affectingthe accuracy.

The components are defined based on their properties which are usuallyrequired for thermodynamic calculations. These required properties varyin different simulators but some common ones are the criticaltemperature, pressure and volume, acentric factor, solubility parameter,liquid molar volume, van der Waals area and volume and latent heat ofvaporization. There is no need to input these properties for the purecomponents because they exist in the simulator's database; however, thecase is different for pseudo-components and their properties arenormally estimated by the correlations and some major input properties,usually normal boiling point, specific gravity and molecular weight.

Oil Components

The Oil Manager in HYSYS is used to input the characteristics of the oilassay in general and the feed in particular. The main input data is theTrue Boiling Point (TBP) distillation curve which is obtained as part ofthe assay. This requires inputting the boiling points of each fractionand the corresponding volume percents in the liquid form at a specificpressure.

Once the assay is defined, the ‘Blend’ tab describes the feed. Any blendin this section will be an arbitrary mixture of oil fractions. The blendis defined as follows:

A temperature is input and the number of cuts with End Boiling Points ofless than this value is input. For example to define the naphtha cuts,the cut End Point of 204° C. is input and then in the cell across therow, number 1 is input showing that there is one cut with a boilingpoint of less than 204° C. In the second row, the temperature of 343° C.as the End Point is input and the number of the cuts is again 1, showingthat there is one cut between 204° C. and 343° C. The same procedure isused to input VGO and the residue. When the blend is submitted, a numberof hypothetical components are automatically created, each representingone oil fraction.

Sulfur and Nitrogen Compounds

The other hypothetical components that are defined separately are sulfurand nitrogen compounds. These two are the base components for HDS andHDN reactions respectively. The sulfur and nitrogen compounds, found ineach cut, are intrinsically different. However, these molecules areclassified into two different classes; the first one including thosepresent in the gas oil cut with boiling points of 300-600° C. and thesecond one including those in the residue fraction. Therefore, onesulfur compound and one nitrogen compound is defined in each of thesetwo classes and HDS and HDN reactions are based on these hypotheticalcomponents. The average properties of such molecules, i.e. density,molecular weight, etc., are used to define such compounds.

Other Compounds

Other compounds that were added to the component list are hydrogen,water, hydrogen sulfide (H₂S) and ammonia (NH₃) which either arereactants or are present in the system.

Components of oil are input to the simulator. Table 2 shows thesecomponents. The names are the simulator's default and can be changearbitrarily:

TABLE 2 The list of components defined in the simulation Name DefinitionBoiling Point Range NBP184 Naphtha Below ° C. NBP296 Middle Distillates204-343° C. NBP441 VGO 343-538° C. NBP829 Residue Over 538° C. S-hydroSulfur compounds in non-residue oil Below 538° C. N-hydro Nitrogencompounds in non-residue oil Below 538° C. S-residue Sulfur compound inresidue Over 538° C. N-residue Nitrogen compound in residue Over 538° C.

Horizontal Well Simulation

As mentioned, the mixture of oil/steam enters the horizontal wellborevia the perforations on its surface. These perforations are placed onthe horizontal casing at intervals of about 15 cm (l′). An approximationof the total number of such perforations is calculated as:

$n = {\frac{L_{T}}{I_{i}} = {\frac{1000m}{0.15m} = 6667}}$

Assuming a production rate of 100 m3/day, the fluid flow rate

$\left( {V_{i} = \frac{V_{T}}{n}} \right)$

for each of these perforations is calculated as 0.015 m3/day.

To simulate the wellbore, the wellbore was divided into 5 segments (anarbitrary number) and 5 corresponding feed entrances which aredemonstrated in FIG. 6. The new feed stream entering each segmentrepresents the combination of the feed streams that drain into thesuccessive pipe segment via its perforations. The length of each segmentis 200 meters and assuming an interval of 15 cm for these perforations,their total number for each segment is

$\frac{6667}{5} \cong 1333.$

Therefore the total flow rate of such a number of perforations is:

$Q = {{0.015 \times 1333} = {{20.0\frac{m^{3}}{day}} = {0.83{\frac{m^{3}}{h}.}}}}$

This flow rate corresponds to the new feed stream before each segment.

As shown in FIG. 6, the first feed stream enters the first pipe segment.Having passed through the first pipe segment, the first feed streammixes with the second feed stream that enters the wellbore at the startof the second segment. The mix stream is directed to the second segment.This procedure continues until the final stream is ready to enter thevertical wellbore.

The feed consists of oil and water with an oil/water ratio of 2. In thesimulation model, two streams were defined for oil and water separatelyto provide control over the model feed. The 5 feed streams in FIG. 6 aremixtures of oil and water streams that have a specific oil/water ratioof 2. Calculations showed that for a total production rate of 100 m3/day(standard ideal volume flow), each oil stream entering has a standardflow rate of 0.28 m3/h which sums to 1.4 m³/h (33.6 m³/day) for the 5streams. Each water stream has a standard flow rate of twice as much asthe oil or 0.56 m³/h.

Simulation Objects

The horizontal production wellbore was simulated in HYSYS using a pipesegment and mixers as shown in FIG. 7. The mixers do not influence theparameters of the system such as the pressure drop. For each pipesegment there is an energy stream by default which is automaticallycalculated based on the heat transfer input data and correlations. Thepipe sizing is based on the information input by the user. Thisinformation determines the inner diameter and pipe material and thenbased on pipe schedules in the HYSYS database, the other data aredetermined. Table 3 shows some of the pipe segment input data:

TABLE 3 Pipe Segment Information Pipe flow correlation Beggs and BrillPipe material Cast iron Ambient medium Ground Ground type Wet sandBuried depth 150 m Inner diameter 146.3 mm Outer diameter 168.3 mmDown-hole pressure 3 MPa Ambient temperature 200° C.

Typical heat transfer data input by the user was as follows:

TABLE 4 Heat Transfer Information For Pipe Segments Insulation type Noinsulation Thickness 0.01 m Ambient medium Ground/Wet sand Buried type150 m Ambient temperature 200° C.

Pressure Drop

Pressure drop in the horizontal section was calculated usingDarcy-Weisbach friction factor:

${\Delta \; P} = {f \times \frac{\rho \; {\overset{\_}{V}}^{2}L}{2D}}$

where V is the velocity of fluid and is calculated as:

$V = {\frac{Q}{\pi \; \frac{D^{2}}{4}}{\left( {Q = {{100\mspace{14mu} m\; 3\text{/}{day}\mspace{14mu} {and}\mspace{14mu} D} = {0.15\mspace{14mu} {{cm}.}}}} \right).}}$

Therefore: V=0.06 m/s

HYSYS calculated the kinematic viscosity of the stream as 0.37 cSt.Therefore the Re number is calculated to be Re=24324 from:

${Re} = \frac{VD}{v}$

To obtain the friction factor, Prandtl's friction factor correlation forsmooth pipes was used:

$\frac{1}{\sqrt{f}} = {{2.0{\log\left( {{Re}\sqrt{f}} \right)}} - 0.8}$

Substituting the Re number into Prandtl's equation, results in an f of0.025.

Thus, the final pressure drop due to the friction on the walls of thewellbore is calculated for a horizontal well of 1000 meters to be 300 Pawhich is negligible.

The effect of scaling the length of the wellbore on the pressure andtemperature profiles was investigated and three different models werecreated to show the effect of the number of pipe segments and feedlocations. Table 5 shows these models.

TABLE 5 Three Different Models For Horizontal Wellbore Simulation Numberof Segment Flow rate of each segments length (m) feed stream (m3/h)Model 1 5 200 0.83 Model 2 10 100 0.42 Model 3 20 50 0.21

The results show that the pressure drop does not change substantially ineither of these models. Also the final temperature of the feed does notshow a significant change (about 5° C. decrease for 1000 meterswellbore). Therefore the scaling used in this model (5 segments) wasmaintained as the base model.

Vertical Well Simulation

Upgrading reactions take place in the vertical section of the wellbore.The heating system, located at the start of the vertical well increasesthe temperature of the oil and water mixture. This increase is assumedto take place within the first 25 meters of the well. This length isarbitrary; however the exact length will be dictated by thepower/intensity of the down-hole heat equipment. The heated section ofthe well is divided into 5 segments which are 5 meters in length. Forhydrotreating reactions, each segment provides a temperature increase of25° C. to eventually increase the stream temperature to 350° C. alongthe first 25 meters of the vertical wellbore. Similarly, for thehydrocracking reactions the temperature will be progressively increaseddepending on the final desired temperature. For a reacting temperatureof 400° C., each segment must provide some 35° C. of temperatureincrease.

The vertical well is simulated as a number of plug flow reactors whichare arranged in series. The reason for using more than one plug flowreactor is to allow for a higher level of control over the modelparameters and to provide better tracking of the gradual increase in theconversions due to temperature and pressure changes along the wellbore.A schematic of the reactor simulation is shown in FIG. 8.

In this figure x_(i) is the conversion taking place in each reactorsegment. The total conversion is given by:

x _(T)=1−(1−x ₁)(1−x ₂)(1−x ₃)(1−x ₄)(1−x ₅)

where x_(T) is the total conversion.

FIG. 9 is the HYSYS process flow schematic for the vertical wellborereactor. Oil, water and hydrogen streams may have different ratios andtemperatures before entering the vertical wellbore. Stream 1 representsthe feed entering the vertical well with a temperature that may bevaried by the user (220° C. in this model). Section 2 shows five plugflow reactors, each 5 meters long, and their energy streams whichcontrol the outlet temperatures. Section 3 is the long plug flow reactorwithout an energy stream whose length may vary between 75 m and 475 m.Section 4 is the product stream.

Simulation Objects

The streams and the mixers in the vertical section are defined similarto those in the horizontal section. The major simulation object that thevertical section contains is the group of plug flow reactors.

The plug flow reactors in this section serve both as the vertical welland as reactors for hydroprocessing reactions. Each plug flow reactor isdefined by 3 major sets of input data: the geometry, the reaction setsand the specific parameters such as pressure drop. The plug flow reactorcan also have an energy stream when an understanding of the heattransfer parameters or temperature changes exist. For the geometry, thedesired length and diameter of the reactor is input as is the value forthe void fraction of the reactor. Each reactor can have one single ormultiple sets of input reactions. For instance in the case ofhydrocracking, four reactions in a network take place simultaneously.However in hydrotreating, only one reaction is active at a time. Thepressure drop due to the hydrostatic head must be independentlycalculated and input.

Pressure Drop

The pressure drop in each segment is mainly due to hydrostatic head andnot friction. The pressure drop due to the friction is calculated forthe vertical wellbore (length 200 m) from:

${\Delta \; P} = {f \times \frac{\rho \; {\overset{\_}{V}}^{2}L}{2D}}$

where the velocity is calculated as:

$V = {\frac{Q}{\pi \; \frac{D^{2}}{4}}{\left( {Q = {{100\mspace{14mu} m\; 3\text{/}{day}\mspace{14mu} {and}\mspace{14mu} D} = {0.15\mspace{14mu} {{cm}.}}}} \right).}}$

Therefore: V=0.06 m/s

Similar to the calculations for the horizontal section, assuming akinematic viscosity of 2 cSt, Re number is calculated as 4900 and thefriction factor is: f=0.038 from Prandtl's equation.

Based on the calculated values, the pressure drop due to the friction inthe wellbore is negligible (171 Pa). Therefore, the total pressure dropwill be due to the hydrostatic head pressure drop only:

ΔP=ρgh

For one segment of 5 meters, the static loss is 37.5 kPa, when ρ=750kg/m3.

Reactions

The hydrotreating and hydrocracking reaction paths and the kineticvalues are based on existing literature data. The power law form of therate equation was chosen as the basis for this study.

r=kC₁ ^(m)C₂ ^(n)

where k=k₀ exp(−Ea/RT), C₁ is the concentration of sulfur or nitrogencompound and C₂ is the concentration of hydrogen.

The data that must be found are the order by which the reactants takepart in the reactions (m and n) and the values of k₀ and Ea for eachreaction. To obtain the most proper reaction paths and kinetic data, twosources where chosen for simulation kinetic model, namely hydrotreatingand hydrocracking reaction data.

Hydrotreating Reactions

In hydrotreating, there are two reactants and two products. In HDS, thesulfur compound and the hydrogen are the reactants and a desulfurizedhydrocarbon and H₂S are the products. The following is the general formof an HDS reaction, where S_(Comp) is the sulphur compound and a and bare the stoichiometry coefficients:

S_(Comp) +aH₂→HC+bH₂S

In the case of HDN the nitrogen compound and the hydrogen are thereactants and a denitrogenized hydrocarbon and NH₃ are the products:

NComp+a′H2→HC+b′NH3

The order of the reactants in the reactions (m and n) and the values ofk₀ and Ea for each reaction was based on literature reported values forHDS and HDN reactions as shown in Table 5.

TABLE 5 Kinetic Data For HDS And HDN Reported By Ferdous Et Al. And UsedIn This Model - Low Boiling Point (<538° C.) Fractions Order k₀ (1/h) Ea(kJ/mol) Scomp <538° C. 1.5 2.7E7 87 Ncomp <538° C. 1   1E6 74

For residue compounds, the kinetic constants are different. For thisstudy, no proper set of data for HDS and HDN reactions of residue oil,with boiling points of over 538° C. was found. Therefore, an approachreported by Trytten et al. was used to calculate the frequency factorand activation energies of residue sulfur and nitrogen compounds basedon the corresponding values in the fractions below 538° C. In thisapproach the authors showed that the rate constants for HDS and HDNreactions decreases logarithmically with increasing the feed averagemolecular weight. The following equation was derived from their figuresto estimate the rate constant for the residue compounds, where anapproximation of their molecular weight is available:

log kR−log k1=−5.3(log MWR−log MW1)

where k1 is the known rate constant of a specific fraction, MW1 is thecorresponding molecular weight, kR is the unknown rate constants ofresidue compounds and MWR is an approximation of the residue molecularweight.

Based on this correlation, an approximate value for both HDS and HDNrate constants of the residue compounds is obtained which is summarizedin Table 6. The activation energy is assumed to be the same as thelighter fraction ones:

TABLE 6 Frequency Factor For HDS And HDN Used In This Model - HighBoiling Point (>538° C.) Fractions k₀ (1/h) Scomp >538° C. 1.6E5Ncomp >538° C.   1E4

Hydrocracking Reactions

The reactants in the hydrocracking reactions are a hydrocarbon andhydrogen. The product is a lighter hydrocarbon of low molecular weight.The following formula represents the general form of a hydrocrackingreaction where HCl represents the heavy hydrocarbon, HC2 is the lighterone and a is the stoichiometry coefficient for hydrogen:

HCl+a H₂→HC2

For instance, HCl can be the residue and HC2 can be the vacuum gas oil(VGO).

For hydrocracking, the order of the hydrocarbons participating in thereaction was considered to be 1. The hydrogen order was assumed to bezero, assuming that the hydrogen is present in excess and at a highpartial pressure.

As previously mentioned, each hydrocarbon family cracks into lighterhydrocarbons through reacting with hydrogen. In other words, theproducts of hydrocracking of heavier molecules are the reactants ofanother set of hydrocracking reactions which cracks these into lightercomponents. As a result, these reactions are not independent and occurthrough a network of reactions. Sanchez et al. suggested the network asshown in FIG. 10.

Calculated values of k₀ and Ea for the reactions paths of FIG. 10 showedthat some of the reactions in this network had very small frequencyfactors and practically did not proceed to considerable conversions.Eliminating the low conversion reactions, a simplified form as shown inFIG. 11 was derived:

As can be seen from FIG. 11, there are four major reactions that takeplace in hydrocracking of oil which are hydrocracking of residue to VGO,hydrocracking of VGO to middle distillates, hydrocracking of residue tomiddle distillates and hydrocracking of residue to naphtha. The kineticdata for conventional catalysts and for all four of these reactions arepresented in Table 8.

TABLE 8 Kinetic Data For The Simplified Hydrocracking Network k₀ (1/h)Ea (kJ/mol) Path 1 7.4E14 202.7 Path 2 3.3E11 165.1 Path 3 4.8E12 184.8Path 4 3.7E10 158.8

It is noted that the residue kinetic data for HDS, HDN and HyCr aredifferent when they are processed as pure components rather than dilutedin lighter fractions. When diluted, the viscosity and diffusionconstraints within the oil are reduced resulting in higher conversions.

Hydrogen Pressure Effect

The hydrogen partial pressure effect was considered in the finalconversion extent. The kinetic data for the conventional catalyst wereobtained from the literature where the hydrogen pressure is higher thanthe one used in this study (3 MPa). For both hydrocracking andhydrotreating reactions, usually but not always, at higher partialpressures of hydrogen higher kinetic constants and consequently higherconversion can be expected and may require correction. In those caseswhere such a correction is not trivial, hydrogen consumption in thereactions at various hydrogen pressures can be an indication of thechange in the conversion level which provides a similar prediction forthe conversion drop.

It should also be noted that if the steam is assumed to be present inthe reaction medium, the hydrogen partial pressure will be even lowerthan 3 MPa depending on the amount of steam present. In severe cases itcan lower the hydrogen partial pressure to an extent that the conversiondrops to zero.

The kinetic data for the ultra dispersed catalysts (discussed below) didnot require the corrections applied to the conventional catalyst data ofthe literature; the reason being that the UD catalyst data are obtainedat pressures near the simulation model conditions.

Reaction Simulations

The reactions may be defined in various forms such as inputting thekinetic data in power law or Langmuir-Hinshelwood forms, introducing theconversion function form based on the temperature or introducing thefunction form of the equilibrium constant based on free Gibbs energy.

Three sets of information are completed to develop each reaction model.The first set contains the stoichiometry information as well as theorder by which each component participates in the reaction rateequation. Note, the reaction order for HDS reactions is 1.5 and for HDNreactions is 1. Hydrogen consumption in hydroprocessing reactions wasused as an indication of the relative volume or mole numbers ofreactants (oil fractions and hydrogen). Using the hydrogen consumptioninformation for the reactions of interest, the correspondingstoichiometry number by which hydrogen takes part in each reaction wasobtained. A summarized example of HDS reactions data is presented inTable 9:

TABLE 9 HDS Reaction Stoichiometry and Orders Component Stoich CoeffForward Order Reverse Order H2 −7 0 0 HC −1 1.5 0 Desulfurized HC 1 0 0(Balanced) H2S 0.414 0 0where HC is the hydrocarbon with sulphur in its structure.

Table 10 shows an example of another set of information required todefine a reaction in HYSYS. These information are:

-   -   The ‘Base Component’ which is the limiting reactant in the        reaction medium;    -   The units for the reactants that take part in the reaction rate        equation; and,    -   The ‘Basis’ which is the form of the ‘Basis Component’ as input        into the model which can be mass fraction, mass concentration,        mole fraction or mole concentration.

The reaction phase which is one of the following cases: liquid, vapour,overall (mixture of both liquid and vapour). The reaction phase forhydroprocessing reactions is normally liquid phase, where the productswill partly join the vapour phase and exit the reactor rather quickly.

TABLE 10 Additional Information For Hydroprocessing Reactions Defined InThe HYSYS Model Basis Mass Fraction Base Component HC Reaction PhaseLiquid Basis Units No units (wt fraction) Rate Units kgmole/m3-h

Knowing that any reaction is the result of both forward and reversereactions happening at the same time, the general form of a kineticreaction is:

r=k×f(Basis)−k′f′(Basis)

where k is the kinetic constant for the forward reaction and is definedas:

k=A×exp{−E/RT}×T ^(β)

and k′ is the kinetic constant for the reverse reaction:

k′=A′×exp{−E′/RT}×T ^(β′)

T is temperature in Kelvin. E and E′ are the activation energies for theforward and reverse reactions respectively.

The final tab in the reaction section inputs the frequency factor, theactivation energy and the β factor. This factor shows the dependence ofk₀ on temperature and is zero in most cases. An example of such a tablefor HDS reaction of non-residue fraction molecules is shown in Table 11:

TABLE 11 Inputting Frequency Factor, Activation Energy And TemperatureDependency Factor For Kinetic Constants A 5.4E8 h-1 E 85 kJ/mol β 0

Results & Discussions

The results include those for hydrotreating including both HDS and HDNreactions, hydrocracking using conventional catalyst in the presence andabsence of water and finally hydrocracking of heavy oil using ultradispersed (UD) catalyst. Conventional catalyst kinetics was found in theliterature for the commonly used catalysts as discussed above. UDcatalyst kinetics are discussed below.

The hydrotreating results show the conversion percents of sulfur andnitrogen compounds and final changes in their weight percent due to thereactions at different temperatures and residence times.

In the case of hydrocracking, the volume percent change at variousresidence times and temperatures for all the fractions are showntogether with the increase in the API gravity of the oil, which is aprimary goal of upgrading. The kinetics of reactions using UD catalystsare shown. In addition, the API gravity increase in the oil using twodifferent catalysts is compared.

Hydrotreating using Conventional Catalyst

The results of hydrotreating are presented at various temperatures andresidence times. Where steam/oil ratio (SOR) is zero and the wellborediameter is kept constant (0.15 m), the residence time only depends onthe length of the wellbore which changes in the simulation runs. Theproduction rate of oil is constant (1.39 m³/h), and it is assumed thatthe water is separated from the system. The residence time is simplycalculated by dividing the volume of the reactor by the production rate.

The results are presented versus the wellbore length rather than theresidence times to provide a better understanding of the physicalrequirements for these reactions. Table 12 can be used as a reference tocompare the residence times and Liquid Hourly Space Velocities (LHSV)corresponding to each reactor length for the aforementioned conditions:

TABLE 12 Residence Times And LHSV Corresponding To Each Wellbore Length(Diam. 15 Cm - Production Rate 1.39 m³/h) Wellbore Length (m) ResidenceTime (h) LHSV (h-1) 100 1.27 0.79 200 2.54 0.39 300 3.81 0.26 500 6.350.16

For the residence times shown in Table 12, the conversion extents forthe HDS reactions of non-residue molecules were obtained through thesimulated plug flow reactors. FIG. 12 shows the results of HDS reactionsof the non-residue lumped fractions (boiling points below 538° C.) andindicates the HDS conversion increases with wellbore length. Alsocomparing the three simulations, higher temperatures result in higherconversions.

The conversion extent for HDS reaction on the residue fraction was alsomodeled. As previously mentioned, the frequency factor reported in theliterature for residue molecules is significantly lower that that ofnon-residue molecules. Therefore, it was expected that the conversionextent would be lower for such molecules compared to non-residue ones.FIG. 13 shows the conversion percents of HDS of the residue fraction andconfirms the expected trend. FIG. 13 also indicates that HDS of residuecompounds does not occur to a considerable extent. For a 500 meterwellbore, the conversion at 375° C. is about 4% where the similar valuefor non-residue lumped fractions is as high as 95%.

Similar simulations were performed for HDN reaction of heavy oil. Againthe results are plotted against the wellbore length at differenttemperatures. The conditions are the same as those in HDS reactions(diameter is 0.15 m and productions rate for oil is 1.39 m3/h). FIG. 14shows the conversion extent for non-residue nitrogen molecules in theheavy oil. The trend is similar to that of HDS conversion and theconversions are higher for higher temperatures and residence times.

The simulation model for the residue fractions in HDN reactions was alsomodeled (FIG. 15). It was noted that considering the low partialpressure of hydrogen, the HDN reactions have low conversion values atthe experiment temperatures. As previously mentioned, the frequencyfactor for residue nitrogen molecules is as low as 1×104 h⁻¹. The smallmagnitude of this value which is two orders of magnitude smaller thanthat of non-residue compounds (1×106 h⁻¹), justifies the inconsiderableconversion of the residue compounds at similar conditions. FIG. 15indicates that the values are lower than those of the HDS. The maximumpoint is for HDN at 375° C. and 500 m well which is only 0.4%conversion.

FIG. 16 compares the results of HDS and HDN reactions at 350° C. anddifferent residence times for non-residue lumped fractions which showsthe considerably higher conversion percent for the HDS reactions of thenon-residue lumped fractions in comparison with HDN reactions. Theresults of HDS and HDN reactions on residue fraction are also comparedin FIG. 17.

When the conversion percent was determined by the simulation model, thesulfur percent of feed and product streams can be compared. A simpleback calculation from the conversion formula provides the product sulfurpercent:

S _(p) =S _(f) −X×S _(f)

where S_(p) is the sulfur percent of the product stream and S_(f) is thesulfur percent of the feed stream and X is the percent conversion. Basedon this calculation, the percent sulfur in the feed and product streamscan be compared. FIG. 18 compares the percent sulfur at differentwellbore lengths at 350° C.

It can be seen that longer wellbores provide deeperhydrodesulfurization. Also as the figure suggests, the decrease in theproduct's sulfur percent is mainly due to the HDS of non-residuecompounds rather than residue compounds. FIG. 18 also shows that themaximum global HDS for 500 meters of wellbore at a reactor temperatureof 350° C. is some 30.6%.

Similar calculations provide the nitrogen percent change in the oilsections. FIG. 19 shows the percent conversion for hydrodenitrogenationfor different oil cuts.

Similar to FIG. 18, most of the percent nitrogen decrease in theproducts of HDN is due to the HDN of non-residue lumped fractions ratherthan residue fraction. Nitrogen weight percent almost does not change inthe residue for any length of wellbore. The global HDN for 500 meters ofwellbore at 350° C. is 13.6%.

Hydrocracking using Conventional Catalyst

The major goal of conventional hydrocracking is obtaining light fuelssuch as diesel and gasoline. Hydrocracking of bitumen targets theproduction of a lighter crude oil through down-hole upgrading. Thus, theproduced oil should have a lower molecular weight than that of bitumen.Through hydrocracking, oil fractions react with hydrogen in the presenceof a catalyst and crack into lighter molecules. This continuous trend ofconversion, gradually changes the proportions of the original oilfractions by reducing the volume percent of the heaviest fractions andincreasing the lighter fractions.

A study of the volume percent change in various fractions of the oil, asa result of hydrocracking was undertaken. The independent variables weretemperature, residence time and steam/oil ratio (SOR). It should benoted that the results may have a percent error when SOR is not zero, asthe presence of water in the system may lower the frequency factor inthe kinetics of hydrocracking reactions and consequently lower theextent of conversions. An extensive search of the available literaturedata was conducted to obtain information regarding this effect on thekinetics of reactions; however no proper data was found. Therefore, inthis study there are only two effects that the presence of water imposesto the system: increasing the velocity of fluids in the wellbore(decreasing the residence times) and decreasing the concentration ofreactants. Both of these effects are detrimental to the conversionextent.

As mentioned above, hydrocracking consists of a network of reactionsthat occur simultaneously. In this network, residue hydrocracks intoVGO, middle distillates and naphtha. Also VGO hydrocracks into middledistillates. Therefore the volume percent of residue is always decliningwhile the middle distillates increase. In the case of VGO, the increaseor decrease of volume percent depends on the extent to which residueconversion proceeds and if this will be higher than that of the VGOconversion into middle distillates. In most cases, as the results show,the volume percent of VGO will increase along with an increase in thequantity of middle distillates. The reason is that kinetic parameters ofresidue hydrocracking into VGO promote a faster reaction than conversionof VGO into middle distillates. In other words, there is an accumulationof VGO in the process of production and conversion, resulting from thefaster production rate in comparison with the conversion rate. Forhydrocracking and for further comparisons, the composition of feed oilis shown in FIG. 20.

Steam/Oil Ratio: 0

For hydrocracking using conventional catalyst in the absence of water,the hydrogen flow rate is 15 kgmol/h and the oil flow rate is 1.389m³/h. The residence times corresponding to each wellbore length, isshown in Table 12.

FIGS. 21 to 24 present simulation model results for hydrocracking atfour different temperatures, namely 425° C., 350° C., 375° C. and 403°C. respectively.

FIG. 21 shows the volume percent increase of middle distillates with anincrease in the wellbore length (residence time). As shown, the VGOincreases by up to 68% at a length of 300 meters and then suddenlydecreases to 60%. The reason is that the amount of residue at 300 metersis so low that its rate of conversion no longer exceeds that of VGO at apoint between 300 and 500 meters. This result implies that VGO from thatpoint on will be converted into middle distillates and there is no netproduction of VGO anymore.

Another result observed in this figure is the constant amount of naphthafractions. It can be seen that the volume percent of this fraction isnot increasing when the depth of wellbore increases to 500 m. Thisresult suggests that the conversion of residue, as the only reactant forproduction of naphtha is very limited and this reaction can not competewith the other two reactions that residue undergoes (hydrocracking intoVGO and middle distillates). This figure is produced at the highesttemperature that the simulations in this work are carried out (425° C.).At lower temperatures, the conversions of these irreversible reactionsare expected to be lower and therefore naphtha conversion will notincrease which was observed through the simulation experiments;therefore, in FIGS. 22-24 naphtha conversion is not shown:

FIG. 22 shows that hydrocracking conversions at 350° C. with aconventional catalyst are very small that there are no major changes inthe volume percents at different wellbore lengths. This is due to thelow temperature level which is not able to promote the reactions toconsiderable extents.

FIG. 23 shows the conversions at 375° C. The volume percents change from100 m to 500 m. The trend of this change, as was mentioned earlier, isthat the volume percent of middle distillates and VGO increase whenresidue decreases. FIG. 24 shows the same trend as FIGS. 22 and 23,however the conversions are higher due to the higher temperature.

Comparing these four figures shows that the middle distillates increasein volume percent through hydrocracking reactions, VGOs may increase ordecrease depending on the amount of residue present and finally residuesalways decreases. It was also noted that an increase in residence timeincreases the conversions in each of the figures by increasing thewellbore length. The effect of temperature increase can also be observedby comparing FIGS. 21-24; however for a clearer view the conversions areplotted vs. temperature at specific lengths in FIGS. 25-28. Note thewellbore diameter is 15 cm and production rate is 1.39 m³/h and thatconversion increases gradually as the simulation model temperatureincreases.

Similar figures were produced for wellbore diameter of 0.1 m. Thisallows for a better comparison of the results over a broad range ofresidence times. The residence times corresponding to each wellborelength are given in Table 13.

TABLE 13 Residence times and LHSVs corresponding to each wellbore length(diameter 10 cm - production rate 1.39 m³/h) Wellbore Length (m)Residence Time (h) LHSV (h-1) 100 0.56 1.77 200 1.13 0.88 300 1.70 0.59500 2.83 0.35

Conditions such as SOR are the same as the previous set. FIG. 29 showsthe volume percent change at 425° C. for all three fractions of oil andthe residue. Similar to FIG. 21, the naphtha volume percent does notchange with length. FIGS. 30-32 show the results of runs at 350° C.,375° C. and 403° C. respectively. FIGS. 33-36 show the results of runsfor different length well bores. The trend of change in the fractions isthe same as the previous set presented for diameter of 15 cm; howeverthe conversions are lower because of small diameter or small residencetime. The volume percent of residue decreases while that of the VGO andmiddle distillates increases. For 350° C. the conversion is so low thatno considerable change in the volume percents is observed.

Steam/Oil Ratio: 1

Results for hydrocracking at a SOR 1 show that the flow rate of water is1.39 m³/h; equal to the oil's. Hydrogen flow rate is as the previouscase and the simulation runs are again based on the conventionalcatalyst. The residence times based on the wellbore length are given inTable 14:

TABLE 14 Residence times and LHSVs corresponding to each wellbore length(diameter 15 cm - production rate 2.78 m³/h) Wellbore Length (m)Residence Time (h) LHSV (h-1) 100 0.64 1.57 200 1.27 0.79 300 1.91 0.52500 3.18 0.31

The results for the volume percent change are presented vs. the wellborelength in FIGS. 37-40 and later vs. temperature in FIGS. 41-44:

The trend in FIGS. 37-44 is similar and shows that the residue decreasesand VGO and middle distillates increase. For a temperature of 350° C.,the conversions are almost zero and for higher temperatures theyincrease. The results of a SOR 1 are also shown vs. the temperature toshow the effect of wellbore length at a constant diameter of 15 cm. Thisdata also shows a similar trend to the previous cases meaning thathigher temperatures can significantly increase the conversions.

Steam/Oil Ratio: 10

Hydrocracking at a SOR 10 was also evaluated as part of this study. Theresidence times are shown in Table 15 and results shown in FIGS. 45-48.

TABLE 15 Residence times and LHSVs corresponding to each wellbore length(diameter 15 cm - production rate 15.27 m³/h) Wellbore Length (m)Residence Time (h) LHSV (h-1) 100 0.12 8.65 200 0.23 4.32 300 0.35 2.88500 0.58 1.73

API Gravity Increase

The API gravity increases by a decrease in the specific gravity of oilas shown:

${API} = {\frac{141.5}{{SG}_{({{at}\mspace{14mu} 60{^\circ}\mspace{14mu} {F.}})}} - 131.5}$

where SG is the specific gravity of the component at 60° F. Any increasein the density of oil, results in a specific gravity increase which thenresults in an API gravity decrease.

To calculate the specific gravity of the mixture the following formulais used:

${SG} = {\sum\limits_{i}{{{Vol}{fr}}_{i} \times {SG}_{i}}}$

Table 16 shows the values for specific gravities of the oil cuts, basedon a typical Alberta bitumen assay:

TABLE 16 Specific Gravity Of Oil Fractions Fraction Specific GravityNaphtha 0.78 Middle Distillates 0.9 VGO 0.96 Residue 1.06

By assuming that the specific gravity values do vary little withconversions, the specific gravity of the product stream is calculatedbased on the volume percents of the oil cuts. Then, using the value ofthe specific gravity of the oil, the API gravity is obtained and can becompared to that of the feed.

FIGS. 49-51 present the API gravity increase as a result of the volumepercent change in the fractions at three different SORs. These figuresshow that any increase in the residence time results in an increase inthe API gravity of the feed. Note the higher temperatures provide higherAPI changes. When the SOR is 10, the steam/oil ratio is very high, suchthat the API gravity change is zero in all cases except for atemperature of 425° C.

As down-hole separation of steam from the oil is not a trivial process,economic evaluations should be conducted to compare the API gravityincrease in the oil at various SORs and investigate if the differencesare encouraging to separate the steam down-hole and if so to whatextent. FIGS. 49-51 compare the API gravity at 425° C. and 403° C. for aSOR of zero, 1 and 10.

As the figures show, the API gravity increases for SOR of zero isslightly higher than that of SOR 1. The comparisons show that a SOR of 1results in a lower API increase. An explanation would say that thedilution of the hydrocarbons in the presence of water reduces the APIgravity change. Higher amounts of water result in a lower concentrationof reactant and consequently lower conversions as shown in FIG. 51.FIGS. 52-53 show API gravity increase at 425 C and 403 C for SOR of zeroand 1.

Hydrocracking Using Ultradispersed Catalyst

The kinetics of hydrocracking reactions using ultra dispersed (UD)catalyst are presented and compared with those of conventionalcatalysts. To obtain UD kinetics, the experimental results ofhydrocracking of a sample of Peace River bitumen were used. Theactivation energy of the UD catalyst is assumed to be the same as thatof the conventional catalyst; however, the frequency factors are higherfor the UD catalyst due to higher available surface area. These k₀values are shown below.

To obtain the kinetic values of the UD catalyst, a method to estimatethese values based on the reaction conversions provided from laboratoryexperiments was employed. The experimental results of hydrocracking onPeace River bitumen provide the conversions of residue, VGO and middledistillates at a specific residence time. The simulation model was runat various k₀ values corresponding to each reaction path in thehydrocracking network to find a new k₀ which would produce a similarconversion to the experimental data. In other words, by trial and errornew k₀ values were found that produced heavy oil with conversionssimilar to those that the UD catalyst produces through the simulationruns in accordance with the hydrocracking reaction network presentedabove.

Table 17 compares the frequency factors of each reaction:

TABLE 17 Comparing the Frequency Factors for Conventional Catalyst andUD Catalyst k₀ (1/h) k₀ (1/h) Reaction Path Conventional Catalyst UDCatalyst 1 7.4E14 5.0E15 2 3.3E11 1.9E12 3 4.8E12 9.6E12

It should be noted that similar to what the literature data forconventional catalysts showed, the k₀ in the conversion of residue tonaphtha for UD catalysts in reaction path 4 is negligible when comparedto that of paths 1, 2 and 3.

By comparing the kinetics of UD catalyst with a conventional catalyst,in Table 17, it can be seen that the UD catalyst have higher k₀ valuesfor hydrocracking reactions. This means that such reactions will havehigher conversions using this kind of catalyst.

The simulation model was run based on the kinetics of the UD catalystand was compared to those for the conventional catalyst. FIG. 54-57shows the results at 425° C., 350° C., 375° C. and 403° C. respectively.FIG. 53 shows that the naphtha volume percent does not change. This isalso the trend for all the other temperatures. In other words naphthavolume percent stays constant. FIG. 58 shows the API gravity increasedue to hydrocracking using UD catalyst at various temperatures of 350°C., 375° C., 403° C. and 425° C.:

FIGS. 59-61 show the API gravity increase for the UD catalyst comparedto that of conventional catalyst and as expected shows a higherconversion and therefore a higher API gravity increase.

Simulation Results Summary

A summary of the simulation results is shown in Table 18.

TABLE 18 Simulation Results Summary Simulation Conditions Result HDS(Hydrogen residence time of 50 min @ over 2 wt % decrease in theDesulpherization): 350° C.; water separated; sulfur content of the crude200 m heavy oil (2 wt % decrease in the distillate, 1.7 wt % decrease inthe residue) HDN (Hydrogen residence time of 50 min @ over 0.03 wt %decrease in the Denitrogenation) 350° C.; water separated; nitrogencontent of the crude 200 m heavy oil Hydrocracking Residence time of 50min @ over 3.5 degree API change 423° C., water separated; 200 mHydrocracking residence time of 50 min @ change in the volume percent423° C.; in the presence of of the three main fractions if water heavyoil is: Middle Distillates: 2% increase - Vacuum Gas Oil: 3% increase -Residue 5% decrease HDS/HDN residence time of 75 min @ heavy oilfractions with 350° C.; water separated boiling points of below 540° C.:80 mol % conversion in the sulfur content in the distillate fraction, 42mol % conversion in the nitrogen content of the distillate fraction

Based on the results generated by the simulation, a partially upgradedcrude oil product with lower amounts of contaminants and enhancedtransporting properties was produced.

Methodologies and Catalyst Compositions

In a preferred embodiment, the catalysts applicable to the invention arecontinuously introduced in the form of a micro-nano particulatedispersed in hydrocarbon media as described in Applicant's co-pendingapplication (U.S. application Ser. No. 11/604,131 and incorporatedherein by reference) or a conventional catalyst or catalyst system suchas a fixed bed catalyst is used.

Different catalyst compositions may be introduced simultaneously withindifferent hydroprocessing zones. For example, catalysts formulated toenable hydrogenation, hydrotreating including desulfurization,hydrodemetalization and denitrogenation and hydrocracking reactions maybe introduced into one or more hydroprocessing zones by means ofseparate or combined injection systems wherein the point of injection ofthe hydrogen and/or catalysts will define the location of one orcatalytic hydroprocessing zones. The catalyst formulation and processconditions may be adjusted such that a suite of in-well processingelements can effect overall upgrading involving both hydrotreating andhydrocracking or other combinations of processes to produce an oil ofdesired quality and specification.

Temperature, hydrogen flow and catalyst flow may be continuouslymonitored and adjusted at the surface based on produced oil compositionanalysis at surface or using in situ sensors in order to adjust thedownhole reactor variables during processing. Such adjustments may bemade in real time using a variety of physical proxies for oil propertiesincluding viscosity, bulk chemical composition, SARA (Saturates,Aromatics, Resins, Asphaltenes) and/or chemical proxies indicative ofthe reaction regime (hydrotreating, hydrocracking, visbreaking etc).

In accordance with one embodiment of the invention, catalystcompositions as described in Applicant's co-pending United Statesapplication, are useful in in situ hydrocarbon upgrading applications.Catalyst compositions, characterized by their particle size and abilityto form microemulsions are described herein.

The catalyst compositions are bi- or tri-metallic compositions dissolvedin a protic medium containing a VIII B non-noble metal and at least oneVI B metal (preferably one or two) in the presence of a sulfiding agent.The atomic ratio of the Group VI B metal to Group VIII B non-noble metalis from about 15:1 to about 1:15. Suitable catalyst compositions can beused in a variety of hydrocarbon catalytic processes to treat a broadrange of feeds under wide-ranging reaction conditions such astemperatures from 200° C. to 480° C.

Bi-metallic catalysts of the general formula:

B_(x)M_(y)S_([(1.1 to 4.6)y+(0.5 to 4)x])

where B is a group VIIIB non-noble metal and M is a group VI B metal and0.05≦y/x≦15 are effective.

In more specific embodiments, 0.2≦y/x≦6 and preferably y/x=3.

A second class of catalysts described as tri-metallic catalysts of thegeneral formula:

B_(x)M1_(y)M2_(z)O_((2 to 3)z)S_([(0.3 to 2)y+(0.5 to 4)x])

where B is a group VIIIB non-noble metal and M1 and M2 are group VI Bmetals and 0.05≦y/x≦15 and 1≦z/x≦14 are also effective.

Further examples of tri-metallic catalysts include those wherein the y/xratio is in the range of 0.2<y/x<6. The range z/x is preferablydetermined by the desired use of the catalyst. For example, selectivityto lighter hydrocarbons (C1-C5) will preferably have a z/x of 10<z/x<14and more preferably z/x=12. Alternatively, selectivity to intermediatehydrocarbons for mild hydrocracking (Low cracking functionality) willfavor 1<z/x<5 and preferably z/x=3.

Formula Examples

As examples, if y/x=0.05, y=1 and x=20. Thus, at this y/x ratio,

B_(x)M_(y)S_([(1.1 to 4.6)y+(0.5 to 4)x])

would include catalyst compositions ranging from B₂₀MS_(11.1) toB₂₀MS_(84.6). If y/x=15, y=15 and x=1, at this y/x ratio,

B_(x)M_(y)S_([(1.1 to 4.6)y+(0.5 to 4)x])

and would include catalyst compositions ranging from BM₁₅S₁₇ to BM₁₅S₇₃.

CONCLUSIONS

The results show that a hydraulic model for a heavy oil wellbore wassuccessfully linked with the kinetics of hydroprocessing reactions. Thehydraulic model showed that the pressure drop in the horizontal sectionwas negligible (300 Pa for 1000 meters of wellbore). The reason for thelow pressure drop is the low velocity of the liquids in the wellborewhich mitigates high friction losses. In the vertical section, thefriction loss was low again due to the low velocity. The major pressuredrop in the system was due to the hydrostatic head of fluids in thevertical wellbore. Also, based on the hydraulic model it was alsoobserved that temperature variations in the horizontal well arenegligible.

Three kinetic models were successfully developed for the hydroprocessingof heavy oil that included hydrotreating using conventional catalystkinetics and hydrocracking using conventional catalyst as well as UDcatalyst kinetics.

It was shown via the simulation model that the major portion ofhydrodesulfurization of heavy oil occurs through hydrodesulfurization oflow boiling point sulfur compounds (under 538° C.) rather than theresidue ones (boiling point over 538° C.). The reason was thesubstantially lower frequency factor that the residue compounds posses.At the longest length of the wellbore (500 m), which corresponds to aresidence time of 6.35 h and at the temperature of 350° C. of theexperiments, it was shown that the hydrodesulfurization conversion ofresidue cuts did not exceed 2% where this number for lighter fractionswas 87%. At these conditions the total sulfur percent change in theproduct was 1.3 wt %. Also the global HDS conversion for the feed at thementioned conditions (6.35 h residence time and 350° C.) was 30.6%.

It was also shown that hydrodenitrogenation reactions, similar tohydrodesulfurization, had higher conversions for the lighter fractionswhen compared to the residue compounds. The conversion extent for awellbore with 500 m length (residence time of 6.35 h) and at 350° C.,for residue nitrogen compounds was 0.2% and for the lighter nitrogencompounds was 60%. The total HDN resulted in 0.03% drop in the nitrogenweight percent. The global HDN conversion was 13.6% for these conditions(6.35 h residence time and 350° C.).

The results of hydrocracking simulation model showed that the residuevolume percent decreased from the feed to the products whereas themiddle distillates increased. It was also shown that naphtha volumepercent stayed relatively constant under various conditions used in thehydrocracking simulation. The VGO volume percent showed either anincrease or decrease depending on the amount of residue present in thesystem to produce VGO. Using the conventional catalyst kinetics, thesimulation results showed that the API gravity of the oil in comparisonwith the feed increased about 9.7 points at a 500 m wellbore (residencetime of 6.35 h) and at 425° C. and SOR of 0. At a SOR 1 the API gravityincreased less than for the SOR 0 (about 1.3 points lower at a residencetime of 3 hours and at 425° C.).

The hydrocracking results were also compared for two different catalystkinetics. The results showed that the hydrocracking conversions werehigher for the UD catalyst in comparison with a conventional catalyst.At 425° C. and residence time of 6.35 (wellbore length 500 m), the APIgravity increase when using the D catalyst was 11.6 which is 1.9 pointshigher than when conventional catalyst kinetics was used. At 403° C.,the API gravity increase using the UD catalyst kinetics was 8.7 whichwas 3.3 points higher than the increase for the conventional catalystkinetics.

In summary, a new method for in-situ upgrading is provided that remediesmany practical problems by using the wellbore capacity for the upgradingreactions. This approach optionally eliminated the need for down-holecatalyst placement by using ultra dispersed catalysts in liquid phasewhich enters the wellbore volume and gets produced with the upgradedoil. In this method, the necessary heat of the reaction is concentratedin the vertical wellbore rather than being introduced to the largedown-hole bitumen reserve in order to minimize the heat loss. Finallythe reactions occur over the ultra dispersed catalysts which offer ahigh effective contact area and have higher kinetic frequency factor forhydrocracking reactions which then results in substantially higherconversions.

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1. A method of upgrading heavy oil in a production well within ahydroprocessing zone comprising the steps of: a. introducing acontrolled amount of heat to the hydroprocessing zone; b. introducing aselected quantity of hydrogen to the hydroprocessing zone to promote adesired hydrocarbon upgrading reaction; and, c. recovering upgradedhydrocarbons at the surface.
 2. A method as in claim 1 furthercomprising the step of introducing a catalyst to the hydroprocessingzone.
 3. A method as in claim 2 wherein the catalyst is a nano-particlecatalyst.
 4. A method as in claim 3 wherein the catalyst is circulatedwithin the hydroprocessing zone.
 5. A method as in claim 1 wherein thehydroprocessing zone is a vertical section of a wellbore.
 6. A method asin claim 1 wherein the method includes separating heavy oil from waterprior to introducing heavy oil into the hydroprocessing zone.
 7. Amethod as in claim 1 wherein the heavy hydrocarbon is bitumen and theupgraded hydrocarbons are characterized by an API gravity increase.
 8. Amethod as in claim 3 wherein the catalyst is a bi-metallic catalyst ofthe general formula: BxMyS_([(1.1 to 4.6)y+(0.5 to 4)x]) where B is agroup VIIIB non-noble metal and M is a group VI B metal and 0.05≦y/x≦15.9. A method as in claim 3 wherein 0.2≦y/x≦6.
 10. A method as in claim 9wherein y/x=3.
 11. A method as in claim 3 wherein the catalyst is atri-metallic catalyst of the general formula:B_(x)M1_(y)M2_(z)O_((2 to 3)z)S_([(0.3 to 2)y+(0.5 to 4)x]) where B is agroup VIIIB non-noble metal and M1 and M2 are group VI B metals and0.05≦y/x≦15 and 1≦z/x≦14.
 12. A method as in claim 11 wherein the y/xratio is in the range of 0.2<y/x<6.
 13. A method as in claim 11 wherein10<z/x<14.
 14. A method as in claim 11 wherein z/x=12.
 15. A method asin claim 11 wherein 1<z/x<5 and the upgrading process is mildhydrocracking.
 16. A method as in claim 11 wherein z/x=3 and theupgrading process is mild hydrocracking.
 17. A method as in claim 1wherein the controlled amount of heat is introduced using any one of ora combination of electrical, hot fluid, or an in-well combustion device.18. A method as in claim 1 wherein the production well includes at leasttwo hydroprocessing zones and a different hydroprocessing reaction iscontrolled in each hydroprocessing zone.
 19. A method as in claim 1wherein the upgrading process is part of a steam flooding processincluding any one of steam assisted gravity drainage (SAGD), vaporextraction (VAPEX), cyclic steam stimulation (CSS) and CAPRI.
 20. Amethod as in claim 1 wherein the upgrading reaction ishydrodenitrogenation.
 21. A method as in claim 1 wherein the upgradingreaction is hydrodesulfurization.
 22. A system for upgrading heavy oilin a production well within a hydroprocessing zone comprising: adownhole heater for introducing a controlled amount of heat to thehydroprocessing zone; a hydrogen delivery system for introducing aselected quantity of hydrogen to the hydroprocessing zone to promote adesired hydrocarbon upgrading reaction; and, a surface recovery systemfor recovering upgraded hydrocarbons at the surface.
 23. A system as inclaim 22 further comprising a downhole water separator for separatingwater from heavy hydrocarbon, the downhole water separator operativelylocated upstream of the hydroprocessing zone.